In the field of subsurface hydrocarbon production, it is known to employ various stimulation procedures and techniques to enhance production. For example, in the case of heavy oil and bitumen housed in subsurface reservoirs, conventional drive mechanisms may be inadequate to enable production to surface, and it is well known to therefore inject steam or steam-solvent mixtures to make the heavy hydrocarbon more amenable to movement within the reservoir permeability pathways, by heating the hydrocarbon and/or mixing it with lighter hydrocarbons or hot water.
Cyclic steam stimulation (CSS) is one of the most promising thermal recovery methods for producing high viscosity oil or bitumen. This oil recovery method requires a predetermined amount of steam to be injected into a well or wells drilled into the hydrocarbon deposit, which well or wells are then shut in to allow the steam and heat to soak into the reservoir surrounding the well and create what is known as a “steam chamber”. This assists the natural reservoir energy by thinning the oil (or, in the case of a steam-solvent injection, also mixing the heavy hydrocarbon with lighter hydrocarbons) so that it will more easily move into the production well or wells. Once the reservoir has been adequately heated and the steam chamber has been created, the production wells can be put back into production until the injected heat has been mostly dissipated within the fluids being produced and the surrounding reservoir rock and fluids. This cycle can then be repeated until the natural reservoir pressure has declined to a point that production is uneconomic, or until increased water production occurs.
Recovery from a CSS well depends on a number of factors, including the production rate for each phase and how long each is sustained. The production rate in turn depends on factors such as the viscosity of the hydrocarbon being produced, the permeability of the reservoir rock and the inflow performance.
Recovery of heavy hydrocarbons such as bitumen requires both mobilizing the hydrocarbon, and then displacing it from the initial position to the drainage points, the producing wells. Displacement is impacted by how mobilised hydrocarbon, condensed water and steam push each other through the reservoir. Each fluid has its own mobility, which depends in part on its viscosity and the permeability available to the fluid. Mobility depends on reservoir rock permeability, pore size distribution, fluid saturation and fluid viscosity. The mobility is a measure of how easy it is for a fluid with a particular viscosity to flow through a rock of a given permeability (Equation 1 below). Each fluid can only flow in its own part of the pore space, and the absolute or rock permeability must be reduced by the appropriate relative permeability to account for the presence of other fluids.
                    Mobility        =                                            k              abs                        ⁢                          k              r                                μ                            1                      where kabs is the absolute permeability in millidarcies (mD), kr is the relative permeability and μ is the fluid viscosity.        
The reduction in this relative permeability greatly affects the ability of the hydrocarbon to be produced at the wellbore.
The movable oil volume (MOV) for each CSS cycle is given by:MOV=PV*(1−Swc−Sorw)  2                where PV is the total pore volume available for occupation, Swc is the connate or irreducible water and Sorw is the residual oil saturation.        
Compaction in a reservoir causes reduction in the movable oil volume as more oil and water are trapped in the pores, whereas dilation increases the movable oil volume. Dilation decreases the residual oil saturation, while the connate water saturation may initially increase to dilate the reservoir grains and later decrease at higher pore volume.
The production of heat from the reservoir also forces the density and viscosity of the downhole hydrocarbon to increase. The former then reduces the rate of hydrocarbon production by decreasing the efficiency of the lifting techniques used, while the latter decreases mobility to the wellbore. This zone of high viscosity that develops in the low-pressure region near the wellbore is commonly referred to as “visco-skin”.
Since at least the 1970s, the use of electrical heaters has been studied for application in heavy oil production. It has been proposed that electrical heaters be introduced in the near-wellbore region of a hydrocarbon production well to optimize production by reducing bitumen viscosity and density resulting from temperature decline and permeability reduction. See for example U.S. Pat. No. 5,339,898 to Yu et al. In the case of visco-skin and reduced productivity, electrical resistance heating has been proposed as a possible solution; see for example Vinsome et al., “Electrical heating”, Journal of Canadian Petroleum Technology, vol. 33, no. 4, April 1994. It has also been noted in the technical literature that continuous, non-cyclic, application of electrical heating has been attempted on several occasions with encouraging results; see for example McGee et al., “Electrical heating with horizontal wells, the heat transfer problem,” Society of Petroleum Engineers Paper No. SPE 37117 (1996); McGee et al., “Field test of electrical heating with horizontal and vertical wells,” Journal of Canadian Petroleum Technology, vol. 38, no. 3, March 1999; McGee et al., “The mechanisms of electrical heating for the recovery of bitumen from oil sands.” Journal of Canadian Petroleum Technology, vol. 46, no. 1, January 2007.
However, the use of electrical heaters appears to have certain disadvantages. For example, the cost of running electrical heaters may be undesirably high depending on the number of wells in production in a given reservoir. Also, the utility of certain types of heaters may be negatively impacted by the presence of steam, which presence is a key driver in a number of thermal recovery methods such as CSS.